Mains phase determination

ABSTRACT

An apparatus and method for remotely determining the phase of a single phase load on a multi-phase power distribution system, including powerline communications and repeaters. The phase determination being based upon comparison of message receipt times.

The present invention relates to determining the phase of public-typeelectric power supplies, ie power supplies provided by utility companiesand the like to the general public, both commercial/industrial andprivate (residential); such power supplies are commonly referred to asthe "mains" (usually for the low voltage portions of the system) or"grid" (usually for the high voltage portions of the system).

For various reasons mains or grid systems are normally 3-phase ACsystems, operating at 50 or 60 Hz. The 3 phases are conventionally takenas R, Y, and B (red, yellow, and blue), and the common (star point) as N(neutral).

It is desirable for the loading of the 3 phases to be broadly balanced.Some types of consuming devices, eg large electric motors, large-scaleheating systems, and the like, are similarly 3-phase. However, manyconsuming devices are single-phase. Commercial and industrial users aregenerally supplied with a 3-phase supply, and to the extent that theirindividual consuming devices are single-phase, they can be encouraged invarious ways to design and operate their systems so that the load theyimpose is broadly balanced. Residential and other small users, however,are normally supplied only with a single phase. The supply companytherefore has to try to balance the load resulting from such consumers,by an appropriate pattern of connection of the different small users tothe 3 phases of the supply.

This balancing can be achieved in various ways. The number ofsingle-phase users will normally be reasonably large, and a randompattern of connection to the 3 phases will therefore generally resultautomatically in a rough balancing. If this is deemed inadequate, then asuitable pattern of connections to the 3 phases can be deliberatelyadopted, eg by connecting houses (or groups or blocks of houses) to the3 phases in a regular pattern.

In general however, the balancing achieved by these methods will only beapproximate. Even if the connections are deliberately made in a patternintended to achieve balance, there will be an imbalance due to differingloads between users of different sizes, and differing patterns of usagebetween different users. Further, as new users require connection andold users require disconnection, there will be changes in the systemwhich will shift the balance.

To achieve a good balance, two things are necessary: knowledge of theactual loadings of the 3 phases, and the ability to adjust theseloadings. It is obviously useless to consider adjusting the phaseloadings without knowledge of their actual loadings. But if thatknowledge is available, then suitable actions can be taken to improvethe balance between the 3 phases. If it is not practical to go outimmediately and change the phase supplied to particular consumers, thensuch changes can be made in the course of other work as that work isrequired; also, when fresh consumers are being connected, they can beconnected to the appropriate phases to improve the general balance.

Knowledge of the loadings of the 3 phases can be gained by monitoringthe mains supplies, eg at transformer and switching stations. However,there are certain difficulties in achieving this; further, this gives noinformation about which consumers are connected to which phases or whatloads the different consumers place on their phases. It is thereforedesirable for the phases and loads of the individual consumers to beavailable.

Hitherto this information has not generally been available, or if it hasbeen available, it has not been in a form which can readily be utilized.Although the loads drawn by the various consumers are of coursemonitored and known, for billing purposes, the phases to whichindividual consumers are connected are often not known, and even if theyare known, it has not been feasible to link this information with thedetailed geographical structure of the supply network.

Systems for the remote reading of meters over the supply network arenow, however, becoming practicable. Such systems use high frequencysignalling over the mains system, typically using FSK signalling in theregion of 3-150 kHz. (There are standards covering such signalling, egthe European CENELEC standard, which reserves the 9-95 kHz band forelectricity suppliers and their licencees.) The geographical structureof such remote meter reading systems automatically matches thegeographical structure of the supply network. The required informationregarding the loads imposed by the different consumers and the loadingof the 3 different phases can therefore readily be generated in a usableform.

But for this to work, the phases of the different consumers must beknown. For a new consumer, this information is apparently readilyavailable, since the phase that that consumer is to be connected to cannormally be determined. But even with this simple situation, logging theinformation into the load balance monitoring system involves anoverhead, and there is the possibility of error in connecting theconsumer or logging the information into the system. With existingconsumers, the problem of identifying their phases is considerablyworse.

The evolution of the supply system over time will also cause problems.There may be phase changes between different sections as a result ofsystem maintenance, involving further overheads in maintaining the loadbalance monitoring system information up to date. Further, sections maybe transferred from one transformer to another, again involvingoverheads in maintaining the system information up to date.

As a result, there are considerable practical difficulties in operatinga load balance monitoring system even with a remote meter readingsystem.

The object of the present invention is broadly to provide a way ofovercoming these difficulties.

Accordingly the present invention provides a remote metering systemcomprising a multi-phase mains supply system having a control unit and aplurality of single-phase consumer meter units with messages passingbetween the meter units and the control unit, characterized by phasedetermining means comprising synchronizing means in the units forsynchronizing their message processing to specific phases of the mainssupply, and means for determining the relative phases of the controlunit and a meter unit from the timing of a message passing between themrelative to the phases to which those units are synchronized. Theinvention also provides a meter unit including phase determining meansas just defined.

The natural geographical area for a remote metering system is the areaserved by a switching or transformer station. This is thus the naturallocation for the control unit, which will be the central station of theremote metering system. The present invention will thus make available,at the central station, information regarding the individual loadingsplaced on the area by the various consumers together with the phases ofthose consumers. This makes it relatively easy to modify the connectionsof consumers in the area to minimize any imbalance, either by changingthe connections of existing consumers or by adding new consumers to theappropriate phases.

The phase to which a meter unit is synchronized will of course be thephase to which it is attached. The control unit will be coupled to all 3phases, so that it can communicate with a meter on any phase; it cantherefore be synchronized to any of the 3 phases. The synchronizationcan be to any distinctive point on the waveform of the relevant phase,eg to the positive-going zero crossing.

In a simple form of the present system, each meter sends out itsmessages to the control unit with their starts at the synchronizationpoint, ie the positive-going zero crossing of its phase. The controlunit compares the instant when it receives the start of the message withits synchronization with, say, the R phase. If the start of the messageas received at the control unit coincides with that station'ssynchronization, then the meter is connected to the R phase; if it isshifted by +120° or -120°, then the meter is connected to the Y or Bphase respectively.

In some situations, it is possible for a meter to be connected the wrongway round, ie with the phase and neutral lines interchanged. Thissituation will be detected by the present system, since the meter signaltiming will be 180° off, ie at 180°, -60°, or 60° (for the R, Y, and Bphases respectively).

The effectiveness of the system is of course limited by the effects oftiming inaccuracies and signal transmission times. But in practice thiswill not cause any difficulties. For a mains frequency of 50 Hz, thecorresponding cycle time is 20000 μs, so the interval between adjacentsynchronization times (allowing for reverse connections) is 1/6 of this,ie some 3000 μs. The message signal frequencies are preferably in theregion of 50-100 kHz, and the message start times can be determined toaccuracies of the order of the signal frequency cycle time, ie 10-20 μs,which is very much smaller than 3000 μs. The signal processing circuitryof the meters and control unit can easily run at frequencies well inexcess of 1 MHz, corresponding to 1 μs, which is in turn much smallerthan 10-20 μs. Further, 3000 μs corresponds to a transmission distancein the region of 100 km, which is very much larger than the area servedby a control unit of any likely remote metering system.

In the system as described so far, messages (or at least those messagesused for phase determination) must be sent out at the synchronizationpoints. This condition restricts the maximum message rate. It istherefore preferred to modify the system to avoid this restriction.

This can be done by including, in each unit, a timer which issynchronized to the synchronization points, and including in eachmessage the count of the timer when the message is actually transmitted.This timer count is equivalent to the phase shift between thesynchronization point and the point at which the message is actuallytransmitted, and the receiving unit can easily take this phase shiftinto account when determining the relative phase of the transmittingunit.

In most remote metering systems, messages will pass in both directionsbetween the control unit and the meters. In such systems, the phase of ameter can equally well be determined by the meter. The control unit willsend out its messages synchronized to the synchronization point, andeach meter will then compare its own synchronization point with theinstant when it receives the start of the message.

The meter must then, of course, include its phase in some message whichit subsequently sends to the control unit. This phase information caneither be included in all messages which the meter sends to the controlunit, or only in response to a specific request from the control unit.It is convenient to adopt the former alternative, since the phaseinformation requires only 3 bits. (There are 6 possible phases for ameter; R, Y, B, and each reversed. These 6 possibilities can easily becoded by 3 bits. This leaves 2 codes unused, either or both of which canbe used to indicate eg error or failure conditions.) This phaseinformation will therefore occupy only a small proportion of anyreasonably sized message.

We have assumed so far that the messages are transmitted directlybetween the meters and the control unit. The signal transmissioncharacteristics of mains systems are however often far from ideal. Therecan be significant attenuation of the signals, and also reflection andhence possible "dead" areas.

As noted above, the natural geographical area for a remote meteringsystem is the area served by a switching or transformer station, whichis thus the natural location for the control unit. However, this naturalarea will often be larger than the area in which direct signalling isreasonably reliable. To achieve effective signalling throughout such anarea, some form of signal relaying or repeating is therefore required.

If the remote metering system uses direct repeating, with no significantdelay of the messages as they pass through the repeaters, then thedetermination of the phases of the meters is not affected. But if thesystem uses some form of message storage and forwarding, then the timingof the messages through the relay stations will be delayed. If the delayis liable to be a significant fraction of a mains cycle, this causescomplications for the present system of determining the phase of themeters.

One way of overcoming these complications is for each relay station tomeasure the time delay between its receiving a message to be forwardedand its retransmission of that message, and to include that time delayin the message, as the phase shift between receipt and retransmission.If a message can be transmitted at any time and includes the phase shiftbetween the synchronization time and the actual time of transmission, asdiscussed above, then the phase shift in the relay station has merely tobe added to the phase shift already in the message.

An alternative way is for each relay station to act as a control unitfor the purpose of determining the phase of the meters with which itcommunicates. The phase of the meter is determined relative to the phaseof the relay station, by means of a message between the meter and therelay station. This phase is then incorporated in a message from themeter to the central station, either as the message leaves the meter (ifthe phase is determined by the meter) or as the message passes throughthe relay station (if the phase is determined by relay station). Thephase of the relay station relative to the central station isdetermined, in the same way, by means of a message between the relaystation and the central station. The central station can then combinethe phase of the relay station and the phase of the meter relative tothe relay station to determine the absolute phase of the meter.

Both these ways of dealing with the presence of a relay station extendnaturally to systems in which there may be a chain of relay stationsbetween a meter and the central station.

A relay station may be coupled either to all 3 phases or to just onephase. In both cases, it is necessary to determine the phaserelationships between the relay station and both the central station andthe meters whose messages it relays.

In the former case, the relay station will receive signals from meterscoupled to each of the 3 phases; since it and the central station may becoupled to the 3 phases differently, the phase relationship of the relaystation relative to the central station also has to be determined. Inthe latter case, the phase relationship of the relay station relative tothe central station obviously has to be determined; the phaserelationship of the relay station relative to the meters with which itcommunicates also has to be determined, since there may be sufficientcoupling in the supply system for a meter on one phase to communicatewith a relay station on another phase.

A form of remote metering system with relaying has been proposed inwhich every meter unit can also act as a relay unit. This form of remotemetering system can obviously support the present system ofdetermination of the phases of the meters, with the meters, when theyact as relay units, performing either the appropriate phasedetermination or the appropriate addition of phase delay into messages.

A remote metering system embodying the present invention will now bedescribed, by way of example, with reference to the drawings, in which:FIG. 1 is a set of waveforms of a 3-phase supply; FIG. 2 is a partialblock diagram of the remote metering system; FIG. 3 is a more detailedblock diagram of the parts of the meters concerned with determining thephase of the meters; and FIG. 4 is a more detailed block diagram of theparts of the central station concerned with determining the phase of themeters.

FIG. 1 shows the waveforms of a 3-phase power supply. There are 3 phasewaveforms. R, Y, and B, each voltage being relative to a common neutralreference level N. Below these waveforms, the synchronization points forunits coupled to them are shown as R, Y, and B; also shown are thesynchronization points R', Y', and B' for units which are coupled tothem in reverse. The synchronization points are taken as thepositive-going zero crossings of the waveforms.

FIG. 2 shows a small part of the remote metering system. There is a3-phase power supply system 10, having 3 phase lines R, Y, and band aneutral line N. There is a central station CS coupled to all 3 phasesand there are 3 meters M1-M3 each coupled to a single phase as shown.(The connections of the meters to the power supply phases will ingeneral be random.) Each meter couples the power supply to a respectiveload L1-L3, and also includes a communications unit CU coupled to thepower supply phase of that meter. Similarly, the central station CSincludes a communications unit CU', coupled to all three phases of thepower supply.

FIG. 3 shows a communications unit CU of one of the meters M1-M3. Thisincludes a message register REG 10 which is coupled to the supply system(by means of modem circuitry, not shown), so that it can transmit andreceive messages. The register 10 includes various fields: for presentpurposes, the fields ID 11, SYN-CT 12, and PH 13 are relevant. Field ID11 is for the identification of the meter: field SYN-CT 12 is for asynchronization count; and field PH 13 is for the phase of the meter.(The message register also has further fields (not shown) for conveyingother information between the central unit and the meter, eg billinginformation, consumption data, and tariff rates. These fields areconcerned with other aspects of the remote metering system which are notrelevant for present purposes.)

The communications unit CU also includes a zero-crossing detector 0/XDET 14 feeding the reset input of a synchronization counter CTR1 15which is continuously fed from a fast meter clock 16. The zero-crossingdetector 14 generates a synchronizing pulse each time the phase withwhich the meter is supplied crosses zero in the positive direction, andresets the counter CTR1, which then counts up until it is reset by thenext synchronizing pulse.

The central station CS includes a communications unit CU' which issimilar to those in the meters. As shown in FIG. 4, this includes amessage register 20 containing; various fields, including the fields ID21, SYN-CT 22, and PH 23, which is coupled through a coupling unit 30 toall 3 phases of the power supply, since the central unit has tocommunicate with meters on all 3 phases. A zero-crossing detector 0/XDET 2-4 is fed from one phase (say R) of the power supply, and feeds thereset input of a synchronization counter CTR1 25 which is continuouslyfed from a fast central station clock 26. The zero-crossing detector 24generates a synchronizing pulse each time the R phase crosses zero(positively), and resets the counter CTR1, which then counts up until itis reset by the next synchronizing pulse.

When the central station sends out a message to a meter, the count inthe synchronization counter CTR1 25 is inserted into the synchronizationcount field SYN-CT 22 of the message being transmitted from the centralunit's message register 20. When this message reaches the appropriatemeter, eg meter M1, it is fed into the meter's message register 10. Thesynchronization count in the synchronization count field SYN-CT 12 isimmediately compared with the current synchronization count in themeter's synchronization counter CTR1 15 by a comparator 17.

Assume for convenience that the counters 15 and 25 cycle through 360counts, ie each starts at 0 and reaches a count of 359 before beingreset. The comparator 17 can conveniently generate 7 different outputs,depending on the difference between the two synchronization counts fedto it:

R: 0-19, 340-359

B' 40-79

Y: 100-139

R': 160-199

B: 220-259

Y': 280-319

F: 20-39, 80-99, 140-159, 200-219, 260-279, 320-339.

These ranges allow identification of the phase of the meter, with afailure or fault (F) range between each synchronization count range fordifferences which are potentially ambiguous. (The fast meter clocks 16and the fast central station clock 26 all run at substantially the samerate, of course.) The bottom part of FIG. 1 indicates, the ranges of thesynchronization counts for the 6 possible phases, with the gapsrepresenting the F state.

This phase result (coded eg into 3 bits) is inserted into the phasefield 13 of register 10, and is included in the next message transmittedto the central station. (That next message will generally be a returnversion of the message which has just been received.) The centralstation includes means (not shown) for storing the phase fields ofmessages received from meter units together with the contents of theidentification fields of those messages, so that it builds up a listingof the phases of the various meters.

The phase field 23 of messages sent out from the central station isempty, and is ignored by the meters. Similarly, the synchronizationcount field of messages sent out by the meters to the central unit isalso empty, and is ignored by the central station. (Obviously, if themessages include suitable type or format codes, these empty fields caninstead be omitted.)

The communications unit CU of each meter also includes a secondsynchronization counter CTR2 18, which is coupled to the synchronizationfield of the meter's message register 10. If the meter has to act as arelay station, it receives a message in its message register forsubsequent retransmission. The synchronization count in the message iscopied into the synchronization counter CTR2 18 as soon as the messageis received. This counter is fed from the fast meter clock, and countsup from the count initially loaded into it. The meter, acting as a relaystation, may store the message for some time before forwarding(retransmitting) it. When it does retransmit the message, on towards itsfinal destination, the contents of the counter CTR2 18 are copied backinto the synchronization count field 12 of the message registerimmediately before the retransmission. Thus the synchronization count ofthe retransmitted message matches the synchronization count which itwould have if it had been transmitted directly from the central station.

Of course, the synchronization counting in counter 18 will normally bemade cyclic, ie reset to 0 each time it reaches 359 (with the count rateassumption above).

It will of course be realized that the functions of the variouscounters, registers, comparators, &c can be implemented in a variety ofways, eg by means of suitable microprocessors and associated memories.

We claim:
 1. A remote metering system comprising a multi-phase mainssupply system (10) having a control unit (CS) and a plurality ofsingle-phase consumer meter units (M1-M3) with messages passing betweenthe meter units and the control unit, characterized by phase determiningmeans comprising synchronizing means (CTR1, FIGS. 3 and 4) in the unitsfor synchronizing their message processing to specific phases of themains supply, and means (17) for determining the relative phases of thecontrol unit and a meter unit from the timing (SYN-CT) of a messagepassing between them relative to the phases to which those units aresynchronized.
 2. A system according to claim 1, characterized in thateach sending unit sends out its messages with their starts at thesynchronization point and, and each receiving unit compares the instantwhen it receives the start of the message with its synchronizationpoint.
 3. A system according to claim 2, characterized in that thesynchronization point is the positive-going zero crossing of its phase.4. A system according to claim 1, characterized in that the phasesdetected comprise R, Y, B, R', Y', and B'.
 5. A system according toclaim 1, characterized in that each unit includes a timer which issynchronized to the synchronization point, and includes in each messagethe count of the timer when the message is actually transmitted.
 6. Asystem according to claim 1, characterized in that the phase of a meterunit is determined by the control unit.
 7. A system according to claim1, characterized in that the phase of a meter unit is determined by thatmeter unit and is included in messages returned by that meter unit tothe control unit.
 8. A system according to claim 7, characterized byrepeater means which relay messages with no significant time delay.
 9. Asystem according to claim 1, characterized by repeater means which storeand forward messages, each relay means measuring the time delay betweenits receiving a message to be forwarded and its retransmission of thatmessage, and including that time delay in the message, as the phaseshift between receipt and retransmission.
 10. A system according toclaim 9 when appendant directly or indirectly on claim 5, characterizedin that the relay means adds the phase shift in the relay means to thephase shift already in the message.
 11. A system according to claim 9,characterized in that the relay means determines the phase of the unitswith which it communicates and incorporates the phase in a message tothe central station.
 12. A system according to claim 9, characterized inthat each meter acts as a relay means.